PRODUCTION LOGGING IN HORIZONTAL WELLS

Abstract

An apparatus for production logging includes a conveyance device configured to traverse a wellbore, a multicapacitance flow meter positioned on the conveyance device and configured to estimate at least one parameter relating to holdup; and a spinner flow meter positioned on the conveyance device and configured to estimate at least one parameter relating to a flow velocity of at least one fluid phase.

Description

BACKGROUND OF THE DISCLOSURE

1. Field of the Disclosure

This disclosure relates generally to oilfield downhole tools and more particularly to tools for logging production wells.

2. Description of the Related Art

Well logging surveys are often made in producing oil and gas wells to determine the fraction of oil, gas and unwanted water components present in a production interval. These data along with measurements of the fluid flow velocity, cross-section of the well, pressure and temperature may be used to determine production rates and other information from each zone of interest in the well. Such data may be useful for optimizing the well production, oil recovery, and water shut-off, in order to achieve a better reservoir management and to reduce intervention costs.

The number of drilled horizontal wells continues to increase. Production logging in horizontal wells can be challenging because of phase segregation due to gravity and fluid density difference. In addition to this, if the well is not perfectly horizontal, the flow regime changes while going up or downhill.

The present disclosure addresses the need for production logging tools and instruments that can operate in such conditions as well as other needs of the prior art.

SUMMARY OF THE DISCLOSURE

In aspects, the present disclosure provides an apparatus for production logging. The apparatus may include a conveyance device configured to traverse a wellbore, a multicapacitance flow meter positioned along the conveyance device and configured to estimate at least one parameter relating to holdup; and a spinner flow meter positioned along the conveyance device and configured to estimate at least one parameter relating to a flow velocity of at least one fluid phase.

In aspects, the present disclosure provides a method for production logging. The method may include conveying a multicapacitance flow meter and a spinner flow meter along a wellbore using a conveyance device, estimating at least one parameter relating to holdup using the multicapacitance flow meter, and estimating at least one parameter relating to a flow velocity of at least one fluid phase using the spinner flow meter.

Examples of certain features of the disclosure have been summarized (albeit rather broadly) in order that the detailed description thereof that follows may be better understood and in order that the contributions they represent to the art may be appreciated. There are, of course, additional features of the disclosure that will be described hereinafter and which will form the subject of the claims appended hereto.

BRIEF DESCRIPTION OF THE DRAWINGS

For detailed understanding of the present disclosure, references should be made to the following detailed description of the preferred embodiment, taken in conjunction with the accompanying drawings, in which like elements have been given like numerals and wherein:

FIG. 1 illustrates a production well that may be logged with devices and methods in accordance with embodiments of the present disclosure;

FIG. 2 illustrates a production logging apparatus in accordance with one embodiment of the present disclosure;

FIGS. 3a-b illustrate one embodiment of an array multi-capacitance flow meter that may be used in a logging tool in accordance with embodiments of the present disclosure; and

FIG. 4 illustrates one embodiment of a spinner capacitance flow meter that may be used in a logging tool in accordance with embodiments of the present disclosure.

DETAILED DESCRIPTION OF THE DISCLOSURE

As will be appreciated from the discussion below, aspects of the present disclosure provide a production logging tool that can operate in deviated and horizontal wells (i.e., non-vertical wells). Illustrative production tools according to the present disclosure may be used to define a flow profile, the perforations contributions, and the water entries. These production tools furnish at least two main measurements, holdup and velocity measurement, which may be used to define the flow profile in a well. Illustrative embodiments are discussed below.

Referring initially to FIG. 1, there is shown an exemplary wellbore 10 having a complex well trajectory. The well 10 has been drilled through the earth 12 and into a pair of formations 14, 16 from which it is desired to produce hydrocarbons. The wellbore 10 is cased by metal casing, as is known in the art, and a number of perforations 18 penetrate and extend into the formations 14, 16 so that production fluids may flow from the formations 14, 16 into the wellbore 10. The wellbore 10 has a substantially horizontal leg 19. The horizontal leg 19 is illustrative of a deviated leg or well section. As used herein, the term a deviated well has an angular offset (inclination or declination) relative to a vertical datum. The well 10 may have multiple sections or legs having various inclinations from a vertical. Additionally, while a cased well is shown, it should be understood that embodiments of the present disclosure may be used in open hole wells. The well 10 may produce multiphase fluids (e.g., water, oil, and gas). FIG. 1 further shows a production logging tool 50 that may be used to log the well 10 despite the phase segregation and changes in flow regime due to changes related to complex well trajectories.

Referring now to FIG. 2, there is shown in greater detail, the production logging tool 50 adapted to define a flow profile, the perforations contributions, and/or the water entries for the well 10. The logging tool 50 may be conveyed along the well using a conveyance device such as a non-rigid tubular 52 (e.g., coiled tubing). The logging tool 50 may be positioned at any location along the tubular 52 (e.g., at a distal end or mid-way along a work string). Any connection arrangement that allows the logging tool 50 to be in fluid communication with the fluids in the well 10 may be suitable. A self-propelled device such as a tractor 53, shown in dashed lines, may also be used to push and/or pull the tool 50 along the well 10. The tractor 53 may be hydraulically and/ or electrically energized and include wheels, treads, expandable pads, or other known devices suitable for enabling movement through the well 10. The production logging tool 50 may include a multi-capacitance flow meter 60 that estimates one or more parameters (e.g., dielectric property) relating to holdup and a spinner flow meter 80 that estimates one or more parameters relating to a flow velocity of a fluid phase or phases.

Referring now to FIGS. 3a and 3b, the multi-capacitance flow meter 60 provides information that may be used to estimate the holdup and the velocity of fluid flow in the well 10 (FIG. 1). As used herein, the term holdup refers to a fraction of a particular fluid present in an interval of pipe carrying a multiphase fluid. In one embodiment, an arrayed multi-capacitance flow meter (MCFM) 60 may have a support structure 62 and is provided with a wing 64. The support structure 62 may be a tool body or housing. An array of linearly distributed holdup sensors is denoted by 66 and 68 Additionally, an array of linearly distributed velocity sensors denoted by 68 may also be used to measure velocity. The tool may measure holdups and velocities with alternating current from two transmitter electrodes and one sensor electrode driven in quadrature: a capacitive electrode and a conductive electrode.

In a horizontal well, the fluid phases segregate horizontally due to gravity and density. The MCFM 60 may measure velocities at multiple levels in such a plane, with six arrays of capacitive sensors, as shown in FIG. 3a, and a mechanical spinner 69 in the center of the borehole.

Referring now to FIG. 4, there is shown one embodiment of a spinner flow meter 80 that is configured to measure in situ (in the well) the velocity of fluid flow in a production or injection well based on the speed of rotation of an impeller. The spinner may be an impeller having a helical or vane shape. The impeller rotates as it is impinged by a flowing wellbore fluid. The impeller angular rotation speed is related to the product of the fluid density and the fluid velocity. The fluid velocity is then used to determine flow rate. In one embodiment, the spinner flow meter 80 may include an electronics module 82 that is in signal communication with a sensor module 84. Sensor module 84 comprises an impeller assembly 86 that is attached to a shaft 90 supported by thrust and radial bearings (not shown). The impeller 86 rotates within the bearings when impinged by fluid flowing in either direction. The impeller 86 has curved surfaces which cause a directional change in fluid momentum as the flow impinges on the impeller 86. The meter 80 may also include other devices such as a fluid typing sensors (not shown) for determining the type of fluid flowing through the impeller 86.

As shown in FIG. 2, the spinner flow meter 80 may include a plurality of impellers 82 that are circumferentially arrayed around a tool centerline. For example, the spinner flow meter 80 may include six or eight impellers 82. Of course, fewer or greater number of impeller/sensor units may be used.

Referring now to FIGS. 1-4, in one illustrative mode of operation, the production logging tool 50 is conveyed into the well 10 and positioned at one or more desired locations. As noted previously, the well 10 may be completed or open hole and the desired location may be a horizontal or at least deviated portion of the well 10. The selected location(s) may have a number of flow conditions that include, but are not limited to: (i) little to no water cut (e.g., less than twenty percent), (ii) high water cut (e.g., more than sixty percent), (iii) relatively high flow velocities, and (iv) little to no mixing of the fluid phases.

When the tool 50 is operated, each instrument, 60 and 80, provides information that may be used to define flow profiles and identify the water entry intervals. For instance, the multi-capacitance flow meters 60 use dielectric data that may be used to estimate holdup (e.g., three phase holdup). The spinner flow meter 80 measures or estimates flow velocity. Generally, the spinner flow meter 80 provides adequate flow velocity information in both high and low water cut and also provides adequate velocity measurement and provide such information even when there is little or no phase mixing. The combination of these measurements, along with the well trajectory and borehole cross section information, may be used for flow profile definition and the identification of the different fluid entries, i.e., oil, water and gas entries.

The term “information” as used herein includes any form of information (Analog, digital, EM, printed, etc.). The “information” may be stored on a suitable media, may be real-time, may include information transmittable via conductor, RF, optical, etc.

Thus, it should be appreciated that what has been described includes a multicapacitance flow meter that estimates at least one parameter relating to holdup; and a spinner flow meter that estimates at least one parameter relating to a flow velocity of at least one fluid phase. The multicapacitance flow meter and the spinner flow meter may be positioned along the same conveyance device. The multicapacitance flow meter may include an array of linearly distributed sensors and may include a plurality of pairs of capacitance sensors. The multicapacitance flow meter may further estimate at least one parameter relating to a fluid velocity. The spinner flow meter may include an array of circumferentially distributed sensors. The spinner flow meter may estimate a flow velocity of at least one fluid phase. The conveyance device may be a non-rigid conveyance member or a self-propelled conveyance device.

it should be appreciated that what has been described also includes a method for production logging that includew conveying a multicapacitance flow meter and a spinner flow meter along a wellbore using a conveyance device; estimating at least one parameter relating to holdup using the multicapacitance flow meter; and estimating at least one parameter relating to a flow velocity of at least one fluid phase using the spinner flow meter. The method may further include conveying the multicapacitance flow meter and a spinner flow meter along a substantially horizontal section of the wellbore. The method, in embodiments, may include locating an out of norm water cut and a region of no fluid phase mixing. An out of norm water cut may be a percentage of water that is outside a desired or expected value or range. The term “minimal fluid mixing” refers to a fluid condition wherein the amount of mixing is below a desired or expected value or range.

While the foregoing disclosure is directed to the certain non-limiting embodiments of the disclosure, various modifications will be apparent to those skilled in the art. It is intended that all variations within the scope of the appended claims be embraced by the foregoing disclosure.

Claims

1. An apparatus for production logging, comprising:

a conveyance device configured to traverse a wellbore;

a multicapacitance flow meter positioned along the conveyance device and configured to estimate at least one parameter relating to holdup; and

a spinner flow meter positioned along the conveyance device and configured to estimate at least one parameter relating to a flow velocity of at least one fluid phase.

2. The apparatus of claim 1, wherein the multicapacitance flow meter includes an array of linearly distributed sensors.

3. The apparatus of claim 1, wherein the multicapacitance flow meter includes a plurality of pairs of capacitance sensors.

4. The apparatus of claim 1, wherein the multicapacitance flow meter is further configured to estimate at least one parameter relating to a fluid velocity.

5. The apparatus of claim 1, wherein the spinner flow meter includes an array of circumferentially distributed sensors.

6. The apparatus of claim 1, wherein the spinner flow meter is configured to estimate a flow velocity of at least one fluid phase.

7. The apparatus of claim 1, wherein the conveyance device is selected from one of: (i) a non-rigid conveyance member, and (ii) a self-propelled conveyance device.

8. A method for production logging, comprising:

conveying a multicapacitance flow meter and a spinner flow meter along a wellbore using a conveyance device;

estimating at least one parameter relating to holdup using the multicapacitance flow meter; and

estimating at least one parameter relating to a flow velocity of at least one fluid phase using the spinner flow meter.

9. The method of claim 8, further comprising conveying the multicapacitance flow meter and a spinner flow meter along a substantially horizontal section of the wellbore.

10. The method of claim 8, further comprising using the multicapacitance flow meter and a spinner flow meter in a flow condition selected from one of: (i) an out of norm water cut, and (ii) a region of minimal fluid phase mixing.

11. The method of claim 8, wherein the multicapacitance flow meter includes an array of linearly distributed sensors.

12. The method of claim 8, wherein the multicapacitance flow meter includes a plurality of pairs of capacitance sensors.

13. The method of claim 8, wherein the multicapacitance flow meter is further configured to estimate at least one parameter relating to a fluid velocity.

14. The method of claim 8, wherein the spinner flow meter includes an array of circumferentially distributed sensors.

15. The method of claim 8, further comprising estimate a flow velocity of at least one fluid phase wherein the spinner flow meter.

16. The method of claim 8, wherein the conveyance device is selected from one of: (i) a non-rigid conveyance member, and (ii) a self-propelled conveyance device.

17. The method of claim 8, further comprising using the estimated at least one parameter relating to holdup and the estimated at least one parameter relating to a flow velocity to estimate a flow characteristic selected from at least one of: (i) a flow profile, (ii) a fluid entry, and (iii) a perforation contribution.

18. The method of claim 17, further comprising using at least one of: (i) well trajectory information, and (ii) borehole cross section information to estimated the selected flow characteristic.